1. Field of the Invention
Embodiments of the subject matter disclosed herein generally relate to blowout preventer systems, interfaces, and methods for determining the health of components of the blowout.
2. Description of Related Art
Well control is an important aspect of oil and gas exploration. When drilling a well, for example, safety devices must be put in place to prevent injury to personnel and damage to equipment resulting from unexpected events associated with the drilling activities.
The process of drilling wells involves penetrating a variety of subsurface geologic structures, or “layers.” Occasionally, a wellbore will penetrate a layer having a formation pressure substantially higher than the pressure maintained in the wellbore. When this occurs, the well is said to have “taken a kick.” The pressure increase associated with the kick is generally produced by an influx of formation fluids (which may be a liquid, a gas, or a combination thereof) into the wellbore. The relatively high pressure kick tends to propagate from a point of entry in the wellbore uphole (from a high pressure region to a low pressure region). If the kick is allowed to reach the surface, drilling fluid, well tools, and other drilling structures may be blown out of the wellbore. Such “blowouts” may result in catastrophic destruction of the drilling equipment (including, for example, the drilling rig) and substantially injure or result in the death of rig personnel.
Because of the risk of blowouts, devices known as blowout preventers are installed above the wellhead at the surface or on the sea floor in deep water drilling arrangements to effectively seal a wellbore until active measures can be taken to control the kick. Blowout preventers (BOPS) may be activated so that kicks are adequately controlled and “circulated out” of the system. There are several types of blowout preventers, the most common of which are ram blowout preventers and annular blowout preventers (including spherical blowout preventers).
Another event that may damage the well and/or the associated equipment is a hurricane or an earthquake. Both of these natural phenomena may damage the integrity of the well and the associated equipment. For example, due to the high winds produced by a hurricane at the surface of the sea, the vessel or the rig that powers the undersea equipment may start to drift requiring the disconnection of the power/communication cords or other elements that connect the well to the vessel or rig. Other events that may damage the integrity of the well and/or associated equipment are possible as would be appreciated by those skilled in the art.
Thus, the BOP may be installed on top of the wellhead to seal it in case that one of the above events is threatening the integrity of the well. The BOP is conventionally implemented as a valve to prevent and/or control the release of pressure either in the annular space between the casing and the drill pipe or in the open hole (i.e., hole with no drill pipe) during drilling or completion operations.
Knowledge of the well conditions is extremely important to maintaining proper operation and anticipating future problems of the well. From these parameters, a well may be more effectively monitored so that safe conditions can be maintained. Furthermore, when an unsafe condition is detected, shut down of the well can be appropriately initiated, either manually or automatically. For example, pressure and temperature transducers blowout preventer cavities to may indicate or predict unsafe conditions. These and other signals may be presented as control signals on a control console employed by a well operator. The operator may, for example, affect the well conditions by regulating the rotating speed on the drill pipe, the downward pressure on the drill bit, and the circulation pumps for the drilling fluid. Furthermore, when closure of the BOP rams is desired, it is useful for the operator to have accurate knowledge of where each ram is positioned.
FIG. 1 shows a well 10 that is drilled undersea. A wellhead 12 of the well 10 is fixed to the seabed 14. The BOP 16 is secured to the wellhead 12. The BOP may be an annular BOP or a ram block BOP or a combination thereof. The annular BOP may include an annular elastomer “packers” that may be activated (e.g., inflated) to encapsulate drill pipe and well tools and seal the wellbore. Ram-type BOPs typically include a body and at least two oppositely disposed bonnets. The bonnets partially house a pair of ram blocks. The ram blocks may be closed or opened under pressurized hydraulic fluid to seal the well.
FIG. 1 shows, for clarity, the ram BOP 16 detached from the wellhead 12. However, the BOP 16 is attached to the wellhead 12 or other part of the well. A pipe (or tool) 17 is shown traversing the BOP 16 and entering the well 10. The BOP 16 may have two ram blocks 20 attached to corresponding pistons 21. The pistons 21 move integrally with the ram blocks 20 along directions A and B to close the well 10. Positions C and D of the pistons 21 may be detected as disclosed, for example, in Young et al., Position Instrumented Blowout Preventer, U.S. Pat. No. 5,320,325 (herein Young 1), Young et al., Position Instrumented Blowout Preventer, U.S. Pat. No. 5,407,172 (herein Young 2), and Judge et al., RAM BOP Position Sensor, U.S. Pat. No. 7,980,305, the entire contents of which are incorporated here by reference.
These documents disclose a magnetostrictive device for determining the position of the piston 21 relative to the body of the BOP 16. These devices generate a magnetic field that moves with the piston and disturbs another magnetic field generated by a wire enclosed by a tube. When this disturbance takes place, a magnetic disturbance propagates as an acoustic wave via the tube to a detector. The time necessary by the magnetic disturbance to propagate to the detector may be measured and used to determine the position of the piston 21 relative to the body of the BOP 16.
Other techniques for measuring the position of the piston are known, for example, the use of a linear variable differential transformer (LVDT). The LVDT is a type of electrical transformer used for measuring linear displacement. The transformer may have three solenoidal coils placed end-to-end around a tube. The centre coil is the primary, and the two outer coils are the secondaries. A cylindrical ferromagnetic core, attached to the object whose position is to be measured, slides along the axis of the tube. An alternating current is driven through the primary, causing a voltage to be induced in each secondary proportional to its mutual inductance with the primary.
As the core moves, these mutual inductances change, causing the voltages induced in the secondaries to change. The coils are connected in reverse series, so that the output voltage is the difference (hence “differential”) between the two secondary voltages. When the core is in its central position, equidistant between the two secondaries, equal but opposite voltages are induced in these two coils, so the output voltage is zero.
When the core is displaced in one direction, the voltage in one coil increases as the other decreases, causing the output voltage to increase from zero to a maximum. This voltage is in phase with the primary voltage. When the core moves in the other direction, the output voltage also increases from zero to a maximum, but its phase is opposite to that of the primary. The magnitude of the output voltage is proportional to the distance moved by the core (up to its limit of travel), which is why the device is described as “linear.” The phase of the voltage indicates the direction of the displacement.
Because the sliding core does not touch the inside of the tube, it can move without friction, making the LVDT a highly reliable device. The absence of any sliding or rotating contacts allows the LVDT to be completely sealed from its environment. LVDTs are commonly used for position feedback in servomechanisms, and for automated measurement in machine tools and many other industrial and scientific applications.
Based on the position of the piston relative to the body of the BOP, various quantities of interest may be derived. For example, Young 1 discloses at column 5, lines 41-49, similar to Judge et al. in paragraph [0038] that “[w]ith the knowledge of the absolute position of the ram, it can be determined if the ram is completely closed, if the ram is hung up, to what degree the packer or wear pad of the front of the ram is worn, and to what degree there is a backlash or wear in the piston mechanism.” However, neither Young 1 nor Young 2 discloses how to determine, evaluate or display these quantities, and Judge et al. '305 describes utilizing plots to obtain information about the ram blocks.
Traditionally, well control operators have relied on flow readings of fluid flow through the ram BOP in order to determine ram functionality. For example, a well control operator may fully open a ram BOP, measure the fluid flow through the ram BOP, and compare the measured fluid flow to an expected fluid flow. The well control operator may also fully close a ram BOP and measure whether any fluid flows through the ram BOP. Based on these readings, the positions of the rams in between the open and closed positions may be extrapolated. However, these techniques introduce a certain amount of uncertainty because the expected flow of fluid through the ram BOP may not be accurate. For example, the composition of the fluids flowing through the BOP may change such that measurements taken may be misleading.
Accordingly, it would be desirable to provide blowout preventer systems, interfaces, and methods that effectively determine and/or display quantities of interest usable for determining the health of various blowout preventer components.